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Collaborating Authors
Reservoir Description and Dynamics
Abstract Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Mineral (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Mobility Of Microemulsions: A New Method to Improve Understanding and Performances of Surfactant EOR
Rousseau, David (IFP Energies nouvelles - The EOR Alliance) | Le Gallo, Clémence (IFP Energies nouvelles - The EOR Alliance) | Wartenberg, Nicolas (Solvay - The EOR Alliance) | Courtaud, Tiphaine (Solvay - The EOR Alliance)
Abstract The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media. The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow. Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment. Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures. These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.
- Research Report (1.00)
- Overview > Innovation (0.60)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Towards More Representative Workflows for Designing Robust Surfactant EOR Formulations
Wartenberg, Nicolas (Solvay - The EOR Alliance) | Blaizot, Dylan (Solvay - The EOR Alliance) | Mascle, Matthieu (IFP Energies nouvelles - The EOR Alliance) | Mouret, Aurélie (IFP Energies nouvelles - The EOR Alliance) | Rousseau, David (IFP Energies nouvelles - The EOR Alliance)
Abstract Designing robust EOR surfactant formulations implies performing a number of experiments related to the impact of variable parameters such as injection brine composition and reservoir temperature from near wellbore to in-depth zones. Performance evaluation assays are commonly employed in parametric studies, ahead of the time-consuming coreflood tests. Phase diagram in tubes and spinning drop tests are commonly used, but they do not easily allow deriving representative values of the o/w IFT and can lead to contradictory outcomes. In this work, we addressed the crucial question of the methods implemented to estimate the IFT in bulk tests and we investigated a model case where the robustness of a surfactant formulation was assessed versus temperature. In the first part, we compared, at optimal salinity, the IFT as classically evaluated by the Huh relationship in tubes to the IFT as determined in a spinning drop tensiometer between, respectively, the microemulsion and the water and oil phases in equilibrated and non-equilibrated situations. In the second part, we evaluated the robustness of a surfactant formulation in terms of IFT versus temperature variation by phase diagrams and spinning drop methods and performed simplified oil recovery coreflood tests, using the CAL-X high throughput device. Results showed that IFT discrepancies up to one order of magnitude exist between the Huh estimation and the spinning drop results as well as between the different strategies for determining the spinning drop IFT. Such discrepancies can be interpreted from a scientific point of view, but they highlight the need to discriminate between the IFT determination methods in view of representativeness regarding the actual oil recovery mechanisms in the reservoir. The tests campaign for the temperature robustness, performed in the 40-90°C temperature range, showed, again, discrepancies between the two bulk methods. Namely, Winsor III situation was observed from 60°C to 90°C in the phase diagrams with an optimum at 70°C whereas ultra-low IFT was observed only at 60°C in the spinning drop tests. The coreflood tests revealed that very good oil recoveries were achieved from 40°C to 90°C, with evidence of formation of oil banks leading to final oil saturation as low as 5% only from 60°C to 90°C. These outcomes suggest that, for cases where the various phases are clearly distinguishable in tubes, phase diagrams should be selected as preferred bulk assays. However, these tests provide only coarse estimates of the IFT, which makes performance prediction based on capillary desaturation curves challenging. For this reason, high throughput coreflood tests could also be included in surfactant formulation design workflows to better forecast for the formulation performances.
- Asia > Middle East (0.46)
- North America > Canada (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Visualization the Surfactant Imbibition at Pore Scale by Using of Fractured Micromodels
Yu, Fuwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Jiang, Hanqiao (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Ma, Mengqi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Xu, Fei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Su, Hang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Jia, Junjian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing)
Abstract Recovery in low permeability oil reservoirs is challenging because they are often high fractured and oil-wet. Microemulsion-forming surfactant solutions, which can replace oil from tight matrix by imbibition, have been verified as effective enhanced oil recovery fluids for tight reservoirs. To better understand the mechanisms of oil recovery from oil-wet, fractured rocks using microemulsion-forming surfactants, microfluidic experiments including single channel micromodel tests and fractured micromodel imbibition tests which could visualize the in-situ phase changes were conducted in this work. Through on our study, the priority of wettability alteration and phase change with a function salinity was clarified. Besides, the imbibition dynamics of microemulsion-forming surfactants at different salinities were provided, and further understanding about the equilibrium process of microemulsion during imbibition was obtained. Based our studies, we suggest a moderate salinity for microemulsion-forming surfactants enhanced imbibition recovery.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
A Continuous and Predictive Viscosity Model Coupled to a Microemulsion Equation-Of-State
Khodaparast, Pooya (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, Russell T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Abstract Surfactant floods can attain high oil recovery if optimum conditions with ultra-low interfacial tensions (IFT) are achieved in the reservoir. A new equation-of-state (EoS) phase behavior model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical non-predictive models based on fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase behavior EoS. The results show that experimentally measured viscosities in all Winsor regions (two and three-phase) are a function of phase composition, temperature, pressure, salinity, and EACN. More specifically, microemulsion viscosities associated with the three-phase invariant point have an "M" shape as formulation variables change, such as from a salinity scan. The location and magnitude of viscosity peaks in the "M" are predicted from two percolation thresholds after tuning to viscosity data. These percolation thresholds as well as other model parameters change linearly with alkane chain length (EACN) and brine salinity. We also show that the minimum viscosity in the "M' shape correlates linearly with alkane chain length (EACN) or viscosity ratio. Other key parameters in the model are also shown to linearly correlate with EACN and brine salinity Based on these correlations, two and three-phase microemulsion viscosities are determined in five-component space (surfactant, two brine, and two oil components) independent of flash calculations. Phase compositions from the EoS flash calculations are input into the viscosity model. Fits to experimental data are excellent, as well as viscosity predictions for salinity scans not used in the fitting process.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Gravity-Stable Processes for Dipping or Thick Reservoirs
Doorwar, Shashvat (Chevron Energy Technology Company) | Lee, Vincent (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Traditionally, all surfactant processes require viscous polymer to mobilize the oil bank. Recent literature shows that for highly dipping reservoirs, a continuous surfactant injection process can be stabilized with gravity alone, by slowing down the processing rate. We extend the gravity stable approach for surfactant slug processes and demonstrate the importance of maintaining gravity stability between slug and chase in addition to gravity stability between microemulsion and slug. Four sandpack experiments were conducted and pictures of the sandpack were taken at regular intervals to provide visual evidence of stable or unstable interfaces. Different color dyes were used to aid visualization of clear fluids. Gravity-stabilized surfactant-only processes eliminate the need of polymer and other facilities associated with surfactant polymer or alkali-surfactant-polymer processes. The slug process described in this paper is a significant improvement on the continuous surfactant injection gravity stable process published earlier.
Abstract The objective of this research was to develop a model to predict the optimum phase behavior of chemical formulations for a given oil based on the molecular structure of the surfactants and co-solvents. The model is sufficiently accurate to provide a useful guide to an experimental testing program for the development of chemical EOR formulations. There are thousands of combinations of surfactants and co-solvents that could be tested for each oil, so even approximate predictions are very useful in terms of reducing the time and effort required for testing and for prioritizing the chemical combinations to test that are most likely to yield ultra-low IFT at reservoir conditions. The effects of changing molecular structures (e.g. swapping head groups, swapping hydrophobes, increasing the length of hydrophobes, increasing the number of PO and EO groups, adjusting the ratios of surfactants) are shown. The variables with the greatest impact on the optimum salinity and solubilization ratio were identified, and methods are proposed to shift the optimum salinity and the optimum solubilization ratios in any desired direction. The structure-property model was developed and tested using a large dataset consisting of 684 microemulsion phase behavior experiments using 24 oils. The chemical formulations used 85 surfactants and 18 co-solvents in various combinations. Both optimum salinity and optimum solubilization ratio (and thus IFT) are modeled whereas other models have focused almost exclusively on the optimum salinity. Predicting the optimum solubilization ratio is actually of more value because of its relationship to IFT. The models include the effects of co-solvent partitioning, soap formation and the molecular structure of both the surfactants and co-solvents.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Assessing Productivity Impairment of Surfactant-Polymer EOR Using Laboratory and Field Data
Izadi, M.. (Ecopetrol S.A.) | Vicente, S. E. (Ecopetrol S.A.) | Zapata Arango, J. F. (Ecopetrol S.A.) | Chaparro, C.. (Ecopetrol S.A.) | Jimenez, J. A. (Ecopetrol S.A.) | Manrique, E.. (Ecopetrol S.A.) | Mantilla, J.. (Ecopetrol S.A.) | Dueñas, D. E. (Ecopetrol S.A.) | Huertas, O.. (Ecopetrol S.A.) | Kazemi, H.. (Colorado School of Mines)
Abstract Surfactant-polymer (SP) flooding (also known as micellar flooding) is an enhanced oil recovery (EOR) process resulting from the interaction of three mechanisms: (1) oil solubilization, (2) interfacial tension reduction, and (3) aqueous-phase mobility reduction by polymer. Surfactant-polymer flooding has been studied both in the laboratory and field pilot tests for several decades. In SP flooding, traditionally a tapered polymer solution follows the injected surfactant slug. However, in recent years, co-injection of surfactant and a relatively high concentration of polymer solution has been used in several field trials. Despite a significant increase in oil recovery in several surfactant-polymer flood projects, the increased oil production period has been of short duration. The first objective of this paper is to present two field pilot tests which encountered productivity impairment, and the second objective is to describe the probable causes of the productivity impairment. The third objective of the paper is to present a methodology, using field and laboratory data, to anticipate the nature of long-term problems. To shed light on the issues, we will present two pilot tests located in the Illinois basin in the United States and San Francisco Field in Colombia. The results of the pilot tests and several laboratory experiments will be presented to address the productivity loss observed in the two pilot projects. Laboratory measurements to determine crude oil propensity for emulsions, with and without surfactants, are not part of the routine chemical EOR protocol in the industry. Nonetheless, understanding the cause and type of emulsion formation in crude oil, brine, and polymer at different salinities is critical and will be presented in the paper. In addition, in the paper, we will present the results of a numerical simulator to evaluate experimental laboratory results and the field test performance. In conclusion, because of the experience with numerous laboratory experiments and the conduct of associated field tests, we will be able to shed light on the complexity of surfactant-polymer EOR field applications.
- North America > United States > Illinois (0.88)
- Europe > United Kingdom > North Sea > Central North Sea (0.45)
- North America > United States > California > San Francisco County > San Francisco (0.25)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Lawrence Field (0.99)
- (8 more...)
Abstract During an Alkaline-Surfactant-Polymer (ASP) flood in reservoir rock, often an in situ microemulsion phase forms upon contact of the injected ASP fluid with the residing oil. These microemulsions form as a result of the required ultra-low interfacial tensions (IFT) for oil mobilization and displacement of the residual oil, but they can have a high viscosity. The success of an ASP flood on oil recovery depends on the complex flow of the injected ASP solution, the mobilized oil and the in situ microemulsion phase, which the latter often has a higher shear-dependent viscosity than the other two. In this study, steady-state (SS) corefloods have been performed to investigate the in situ microemulsion formation and rheology during the multiphase flow. The aqueous phase, namely brine, AS or ASP, was co-injected with n-decane or reservoir ‘dead’ crude in Berea outcrop cores for a range of fractional flow ratios. The pressure differential was continuously recorded, and was then converted in an apparent, in situ, viscosity value. For this stage of the project the water and oil phase saturations in the plugs were not yet measured. For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points. It is anticipated that this study leads to a fast and fit for purpose characterization method of ASP-crude oil systems that provides data in a form, such as relative permeability data and residual oil saturation that can be applied directly in reservoir simulators.
- Europe (0.68)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Identifying and Evaluating Surfactant Additives to Reduce Water Blocks after Hydraulic Fracturing for Low Permeability Reservoirs
Liang, Tianbo (The University of Texas at Austin) | Achour, Sofiane H. (The University of Texas at Austin) | Longoria, Rafael A. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin) | Nguyen, Quoc P. (The University of Texas at Austin)
Abstract Significant amount of fracturing fluid is lost after hydraulic fracturing, and it is believed that the loss of fluid into the matrix can hinder the hydrocarbon production. One way to reduce this damage is to use the surfactants. Robust surfactant formulations have been developed for chemical enhanced oil recovery (CEOR); similar ideas are introduced in this study to reduce water blocks in low permeability reservoirs. Here we present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production within the rock near the fracture face. Different levels of IFT reductions are tested and compared in order to explore the best condition that maximizes the permeability enhancement. The effect of in-situ microemulsion generation to mobilize the trapped water is also studied. From this work, we recognize the mechanism responsible for the permeability damage in matrix and we suggest criteria to optimize the performance of surfactant additives so as to enhance the hydrocarbon production from low permeability gas/oil reservoirs after hydraulic fracturing.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)